Wells are generally drilled into the ground to recover natural deposits of hydrocarbons and/or other desirable materials trapped in geological formations in the Earth's crust. A well is drilled into the ground and/or directed to a targeted geological location and/or geological formation by a drilling rig at the Earth's surface.
Once a geological formation of interest is reached in a drilled well, drillers often investigate fluids of the geological formation (i.e., formation fluids) by taking fluid samples from the formation for analysis. In some examples, one or more formation fluid samples are obtained by lowering a fluid sampling tool into the well and withdrawing the fluid samples from an underground formation. One example of a sampling tool is the Schlumberger Modular Formation Dynamics Tester (MDT™). The fluid samples may then be analyzed (e.g., in a laboratory) to determine one or more characteristics of the fluid. Additionally or alternatively, characteristics of a fluid may be measured and/or the fluid may be analyzed (e.g., within the sampling tool itself and/or by a device communicatively coupled to the sampling tool) while the sample is relatively pristine. Moreover, such downhole fluid characterization and/or analysis provides information in substantially real-time in contrast to a laboratory analysis that may require many weeks or months to be completed, and/or surface well site analysis, which may result in undesirable phase transitions as well as the loss of key constituents. if the sampling pressure is above the saturation pressure, the fluid will most likely be in a single phase ensuring that the original composition is being analyzed. For pressures below the saturation pressure, a measurement of the properties of a liquid phase sample taken in the reservoir oil zone, and of an associated gas sample taken above the oil zone, will yield more accurate values than a measurement of the properties of a sample recombined at the surface. Indeed, it may be difficult to retain the sample recombined at the surface. Indeed, it may be difficult to retain the sample in the state in which it existed downhole when it is retrieved and/or removed to the surface.
Petroleum oil and gas are essentially a mixture of several hydrocarbon components, the variation of which dictates the characteristics of the fluid, along with some inorganic substances. Different types of reservoir fluids include black oils volatile oils, retrograde condensates, wet gases, and dry gases, and the different fluid types require different considerations for their exploitation, and different properties are used for their description. For example, it is generally agreed that black oils can be described satisfactorily using averaged properties of the oil and gas phases, such as the volumetric factors and gas solubility ratios. volatile oils and retrograde condensates, which are near critical fluids, as well as wet gases all require a more detailed knowledge of the fluid composition because the ultimate recovery will be dictated by the control of the production conditions (e.g., primarily pressure).
The analysis of a collected fluid sample provides information about the contents of the fluid, density, viscosity, saturation pressure (e.g., bubble point pressure or dew point pressure), and other important characteristics. This vital information is used for field planning decisions and/or for the optimization of upstream and/or downstream production facilities. Indeed, decisions such as the type of well completion, production procedures and the design of the surface handling and processing facilities are affected by the characteristics of the produced fluids. For example, if fluid in the well is a retrograde condensate, the saturation (dew) pressure, combined with the formation pressure and permeability, dictate the maximum pressure drawdown for production of the fluids, and/or whether an injection scheme for pressure maintenance for liquid vaporization should be implemented.
One fluid characteristic of particular interest is the gas-oil-ratio (GOR). The GOR is the ratio of the volume of the gaseous phase in the formation fluid and the volume of liquid hydrocarbons, at standard conditions (e.g., 60 degrees Fahrenheit and 1 atmosphere of pressure). GOR values are typically expressed in units of standard cubic feet of gas per barrel of oil (scf/bbl) at the standard conditions. The GOR, among other formation fluid parameters and/or values, is important in designing the upstream and/or downstream production facilities. for example, if the GOR is high, the surface facilities must be designed to handle a large amount of gas from the well.